7 World Energy Council 2013 Cost of Energy Technologies 5 The World Energy Council (WEC) and Bloomberg New Energy Finance (BNEF) have partnered to produce a comprehensive comparative study of the costs of producing electricity from a wide range of conventional and non-conventional sources. The aim and the unique value proposition of the study is to provide reference costs based on real project data, focusing on the leading renewables and conventional technologies across a range of regions worldwide. This is a joint BNEF/WEC report prepared for presentation at the 22 nd World Energy Congress in Daegu, Korea (Rep. of). The report covers utility-scale wind, solar PV and solar thermal, marine, biomass, hydro and geothermal. Costs of producing electricity vary significantly around the world and across different energy sources. Any quantitative report or study is as good as the data and other information used for its production. To ensure that this report stands out in the crowded market space of energy related studies, it was very important to have access to the best data available in WEC Member Committees and their member companies. For further work on this topic, stronger support of WEC membership in procuring the required data will be crucial. It could make this project a sustainable top class reference source serving the needs of the entire WEC community. This should be considered a pilot study for upcoming studies with BNEF. We expect that this report will contribute to encouraging more utilities to participate in the next surveys by demonstrating that the benefits of having access to relevant cost information are much higher than the hypothetical risk of confidentiality. Finally, one technical remark on the Levelised Cost of Electricity (LCOE) values. LCOE demonstrate electricity generation costs only, and thus do not represent the total cost of electricity supply such as grid connection or balancing costs for integration of volatile and intermittent RES (wind, PV). Neither does it include the costs of required back-up capacity based on conventional thermal plants, occasional capacity shedding and other additional system costs. Technology coverage The study aims to reflect both the relevant cost ranges for producing electricity from each renewable energy technology as well as the key drivers of projects costs. These include the cost of financing as well as equipment, installation, operating and maintenance and fuel costs where applicable. Four cost metrics are presented for each technology (see Methodology) uu uu uu uu Capital expenditure (CAPEX). This includes the total cost of developing and constructing a plant, excluding any grid-connection charges. Operating expenditure (OPEX). This is the total annual operating expenditure from the first year of a project s operation, given in per unit of installed capacity terms. Capacity factor. Also referred to as load factor, this is the ratio of the net megawatt hours of electricity generated in a given year to the electricity that could have been generated at continuous full-power operation, or 8,760 full hours. Levelised cost of electricity (LCOE): a USD/MWh value that represents the total lifecycle costs of costs of producing a MWh of power using a specific technology. Note that the analysis only covers projects greater than 1MW in capacity, as the economics of smaller distributed generation like rooftop PV for example differ substantially from those of larger projects and the collection of high quality data becomes problematic. For

8 6 Cost of Energy Technologies World Energy Council 2013 the most mature technologies the cost metrics are generally shown for the following regions, depending on the level of deployment and availability of data: uu uu uu uu uu US & Canada Western Europe China India Japan Table 1 Technologies covered by this report Source: Bloomberg New Energy Finance Class Technology Sub-types Renewables Conventional Wind Solar PV Solar thermal Marine Hydro Biomass Geothermal Coal Gas Nuclear Onshore, offshore (excluding grid connection costs) Crystalline silicon with and without tracking, thin film Parabolic with and without storage, tower and heliostat with and without storage Tidal, wave Large hydro >10MW, small hydro <10MW, run-of-river Incineration, landfill gas, municipal solid waste, biogas Binary, flash Introduction to the levelised cost of electricity methodology The levelised cost of electricity (LCOE) is the price that must be received per unit of output as payment for producing power in order to reach a specified financial return or put simply the price that project must earn per megawatt hour in order to break even. The LCOE calculation standardises the units of measuring the lifecycle costs of producing electricity thereby facilitating the comparison of the cost of producing one megawatt hour by each technology. The simple formula for this calculation is shown below and is denominated in USD/MWh, where USD are in 2012 prices: In practice LCOEs for this report are calculated using a more sophisticated discounted cash flow (DCF) model. This allows us to capture the cost impact of the timing of cash flows, development and construction costs, multiple stages of financing and interest and tax implications of long-term debt instruments and depreciation, among other factors.

9 World Energy Council 2013 Cost of Energy Technologies 7 The LCOEs presented in this report reflect the actual costs of each technology and exclude all subsidies and support mechanisms. This facilitates a comparison of the total costs of each technology on an equal basis, but does not represent the net costs faced by developers in the market. The figures used reflect the most recent data available with preference for costs from Q1 and Q This is possible for the most widely deployed technologies in larger markets, but for certain technologies where there have been few or no recent installations such as solar thermal older figures are used. Costs also exclude the expense of connecting to the grid network, balancing costs and the cost of maintaining adequate flexible capacity in the electricity system to ensure continuous supply as more intermittent, renewable, capacity increases. Data collection and the WEC network The data used in this report draws extensively on BNEF s proprietary database of clean energy projects and their associated operating, financing and construction costs. The report has also benefited greatly from the knowledge and data available across WEC s global network. In spite of the good coverage of this report it is acknowledged that some data gaps remain, on both a geographic and technology level. These will be addressed in future editions of this report.

11 World Energy Council 2013 Cost of Energy Technologies 9 The information below refers only to generation of electricity, and does not present the total cost of supply, i.e. transmission and distribution costs which can often account for a significant share of these total supply costs. Globally coal is still the king of electricity production, accounting for over 1.8 terawatts of installed generation capacity. Electricity production from fossil fuels coal, gas and oil makes up roughly 65% of global power generation, but in 2012 net investment in renewable power capacity outpaced that of fossil fuel generation for the second year in a row (USD228bn for renewables versus USD148bn for additional fossil fuel generation). 1 Figure 1 Global nameplate installed electricity capacity versus net generation, 2011 Source: Bloomberg New Energy Finance (renewables), EIA (coal, gas, liquids), PRIS (nuclear). Nuclear capacity includes only operational plants, not those defined by the IAEA as being in long-term shutdown. Note: net generation for central producers as defined by the EIA Other renewables 0.1% PV 1.8% Geothermal 0.2% Biomass 1.9% Total: 5,161 GW Oil 7.3% Wind 5.2% Nuclear 7.1% Hydro 18.2% Gas 22.6% Total: 20,726 bn KWh Wind 2.8% Nuclear 13.1% Hydro 15.7% Gas 18% Other renewables 0.1% Oil 0.2% PV 0.5% Geothermal 0.4% Biomass 3.3% Coal 35.6% Coal 46% Capacity Generation However the global share of generation output from renewable technologies is expected to rise from roughly what was 23% in 2010 to around 34% in Clean energy investments have risen strongly over the past decade, growing seven fold from 2004 to Wind and solar will continue to dominate. Wind (on and offshore) is projected to rise from 5% in 2012 to 17% of installed capacity by 2030, overtaking large-hydro. Starting from a lower base, solar PV capacity should grow from 2% in 2012 to16% by A significant amount of this growth is due to the projected decrease in the costs of these technologies especially for PV which will see it become cost competitive with conventional sources of power in several markets. This is particularly the case in regions with good solar resources and high power costs (pre subsidy), such as the Middle East. Other renewable sources, such as marine, geothermal and solar thermal, benefit from being more controllable, but will make a smaller contribution than wind and solar due to their higher costs and more limited resources. In spite of the growth in renewable capacity, fossil-fuel generation capacity will grow in absolute terms in all scenarios, although its relative contribution will fall from 67% in 2012 to 40 45% by The growth in coal capacity will slow significantly due to the imposition of carbon pricing schemes and local environmental concerns, especially in terms of air quality. Gas will 1 Bloomberg New Energy Finance/UNEP, Global Trends in Renewable Energy Investment, 2013

12 10 Cost of Energy Technologies World Energy Council 2013 continue to increase its share of the global electricity mix, particularly in North America, but the relatively high cost of LNG will constrain the growth of gas as a source of power in Europe, the Middle East and Asia. Nuclear s share is expected to remain steady at around 6%. Figure 2 Cumulative installed power generation capacity (GW) Source: Bloomberg New Energy Finance. Note: forecast is from BNEF New Normal forecast scenario from the BNEF Global Renewable Energy Market Outlook: 10,000 Marine 9,000 Solar thermal 8,000 7,000 Small-scale PV Solar PV Offshore wind 6,000 Wind 5,000 4,000 Energy from waste Biomass Geothermal 3,000 Hydro 2,000 1,000 Nuclear Oil Gas Coal Global LCOE ranges BNEF already provides a quarterly assessment of global LCOEs for clean and conventional technologies in well developed markets. Figure 3 shows the most recent figures for each technology across the world, as of the beginning of Q The LCOE analysis shows that there is a wide cost spectrum across the renewable energy technologies. The more mature clean energy technologies such as hydro and onshore wind, when sited in a good location, fall close to parity with traditional sources, while more emerging technologies such as marine tidal and wave are still at the early phases of cost discovery. Over time the cost of producing electricity from a given technology should fall at a rate related to the level of deployment, a phenomenon known as the experience curve. Over the past few years LCOEs for PV and onshore wind have fallen dramatically as governments have provided financial support that has encouraged rapid deployment, causing the cost of manufacturing those technologies to come down while the efficiency of producing electricity from them has increased. A key component in the LCOE of renewable technologies is the cost of finance and this varies by technology and location. Typically the more mature technologies of onshore wind and solar PV are accepted as relatively low risk and gain more favorable financing terms. The financing of offshore wind projects however is still highly project specific, depending on the distance from shore, construction technology used and experience of the developer.

14 12 Cost of Energy Technologies World Energy Council Costs by technology

15 World Energy Council 2013 Cost of Energy Technologies 13 Wind Between 2000 and 2010 the global capacity of onshore and offshore wind increased an average of 30% per year, reaching 200GW installed in was a record year for new onshore wind installations with over 46GW of capacity built in the year. Offshore wind is just beginning to be installed at scale and BNEF forecasts that by 2020 global capacity will reach nearly 50GW. Regionally, Europe, the US and China account for the bulk of onshore wind capacity while offshore capacity is focused off the coast in Europe with development also occurring along the snore lines of China and South Korea. China will likely be a major force in the future for offshore wind, but delays affecting current projects continue to push out the deployment horizon. Since BNEF began tracking onshore wind LCOEs in mid-2009, values have fallen by 18%, a rate greater than the turbine experience curve, as a result of increasingly cheaper construction costs and higher capacity factors. Meanwhile offshore LCOEs have crept upwards, reflecting the increased costs of projects further from shore coupled with cost overruns due to harsh construction environments and the complex nature of construction at-sea. Figure 4 Levelised cost of wind electricity over time, developed market average (USD/MWh) Source: Bloomberg New Energy Finance Offshore Onshore 50 0 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q Onshore wind Core technology costs and performance Wind turbines make up the single largest component of the CAPEX required for an onshore wind installation, roughly 63% of total cost. The remaining components include concrete foundations, on-site electrical and site-preparation and transport. Depending on a project site s location relative to the manufacturing facility supplying the turbines, transportation costs can cause total CAPEX to increase substantially. The makeup of the global turbine manufacturing industry can be broken into two distinct segments: Chinese manufacturers, which accounted for approximately 40% of supply in 2012 and global manufacturers, which account for the remainder. Manufacturing facilities are spread globally. Turbine costs, as measured by the Bloomberg New Energy Finance Wind Turbine Price Index, are down nearly 30% from peak prices in 2008, as measured in Euros. A growing split however has emerged between the prices paid for older models versus newer models. Older model turbines continue to decline in price while newer models have become more expensive,

16 14 Cost of Energy Technologies World Energy Council 2013 reflecting the premium paid for the increased efficiency offered by new turbines. Newer models are targeted specifically at lower resource areas as they are able to extract more energy from lower speed winds than older models. This higher efficiency can result in a lower levelised cost. Certain markets, such as Brazil and parts of Latin America, continue to be dominated by older, less expensive models due availability of high quality wind resources. Low capital expenditure helps pull down the LCOEs of onshore wind in India and China, making well-sited projects there among the cheapest in the world. The lowest LCOEs for onshore wind can be found in India, particularly in higher wind resource areas such as Karnataka where load factors can exceed 33% and project CAPEX can drop below USD1.1m/ MW resulting in LCOEs below USD50/MWh. This is despite some of the world s most costly debt financing: project borrowers can be forced to pay over 1,100 basis points (bps) over LIBOR as the result of a risky lending environment. In China the best project economics can be found in Inner Mongolia, where low domestic turbine prices combined with 35%+ load factors bring LCOEs to around USD48/MWh. Despite attractive economics there are significant logistical barriers to project installations in these remote regions, as well as the well-documented issue of finished projects being unable to successfully connect to transmission infrastructure. O&M costs for projects in China are not significantly different to those of Western Europe, which relate to the reduced reliability of turbines in the Chinese domestic market that therefore require increased maintenance. Project borrowers in China can expect to pay around 700 basis points over LIBOR for 12 year loans accounting for 75% of total CAPEX. On the high end globally is Japan a recurring theme where exceptionally high equipment costs, a lack of development experience, a competitive market and high OPEX resulting from some of the most expensive labour costs in the world (estimated as a percentage of CAPEX due to lack of data) combine to drive LCOEs up over USD300/MWh. The Japanese market has only just kicked off as of late 2012, driven by a generous feed-in-tariff which has already been reviewed and downgraded. Figure 5 Levelised cost of onshore wind electricity by region (USD/MWh) Source: Bloomberg New Energy Finance Japan Europe Australia United States Brazil China India LCOE range Mid In the middle of the extremes lie North America and Europe. All-in CAPEX in the US tends to be slightly more expensive than in Western Europe and comes in at around USD1.8m/MW versus around USD1.6m/MW in markets like Germany and the UK. The developing wind markets of eastern Europe ring in a bit higher, at between USD m/MW depending on site and shipping. The key LCOE differentiator is load factor. In certain US regions, such as the

17 World Energy Council 2013 Cost of Energy Technologies 15 Great Plains and parts of Texas, onshore load factors can reach 45%+, putting end LCOEs at USD50 or lower. Finding sites with that level of resource in western Europe can prove challenging, not least because of sheer population density and land unavailability. Load factors for plants with older model turbines average 25% 28% for countries like Germany, Italy and Spain, with parts of the UK able to obtain higher rates. The application of newer models, while increasing CAPEX, can push up averages to 28 31%. Annual O&M rates are generally higher in Europe than in the US. The UK and Eastern Europe s limited supply chain pushes annual contract charges to USD28,000 29,000/MW/yr, while in more competitive markets like Sweden that also site larger scale projects able to benefit from economies of scale costs can drop below USD20,000 USD24,000/MW/yr. The US and Brazil similarly competitive, are both characterised by large scale projects and O&M contracts of around USD23,000/MW/yr or less. In BNEF s developed market scenario, a standard onshore wind farm with a capacity factor of 32%, USD1.77m/MW CAPEX and access to 77% debt financing has an LCOE of USD78/MWh. Table 2 Levelised cost of onshore wind by country Source: Bloomberg New Energy Finance Note: *the given range is an average scenario range and does not reflect actual maximum and minimum values Geography CAPEX (USDm/MW) OPEX (USD/MW/yr) Capacity factor (%) LCOE (USD/MWh) India ,694 24, China ,000 25, Brazil , United States ,000 24, Australia , Europe ,000 28, UK* , France* ,000 22, Germany* ,000 21, Sweden* ,000 21, Netherlands* ,000 22, Denmark* ,000 22, Italy* ,000 22, Spain* ,000 22, Poland* ,000 24, Romania* ,000 24, Bulgaria* ,000 23,

18 16 Cost of Energy Technologies World Energy Council 2013 Policy & financing Onshore wind new-build in the US is incentivised by the production tax credit (PTC), which is currently due to expire at the end of 2013 after a one year extension in late Legislative brinksmanship with the tax credit in late 2012 prompted a rush of new installations before December projects that would otherwise have been built in 2013, leading to a forecasted decline in that market. Financing costs in the US are on par with those in Western Europe: bps over LIBOR for term loans accounting for 70 80% of project costs at tenors of 8 10 years. In Europe Germany, Denmark, Spain and the UK are the major markets for onshore wind, but the strong government support of the past has been wavering, particularly in Spain. Developers would perhaps be reassured by clearer policies and greater financial visibility. In Europe, the capacity addition tempo is driven primarily by the attractiveness of government-set feedin-tariffs, which have been under pressure as austerity measures have been implemented across broad swaths of the continent. Overly-generous support levels in the past have incentivised the construction of projects that would otherwise be very uneconomic. Even recently developed markets aren t immune: Romania slashed its allocation of green certificates to all clean energy projects in June, causing forecasted installations from 2014 forward to fall precipitously. Financing costs in the more stable economies of Western Europe fall in the range of bps over LIBOR for increasingly shorter semi-perm loans of 5 8 years. This type of shorter-term loan is a reflection of the banking regulatory environment there, which is causing lenders to shorten the duration of the loans and encourage frequent refinancings. In the less-stable markets in Southern and Eastern Europe borrowers can expect to pay 500bps or more over LIBOR as a reflection of high sovereign risk. China s 2015 wind capacity target of 100GW is likely to be surpassed to the tune of 30GW to a total of 128GW installed, of which 113GW is forecasted to be grid-connected. Grid-connection can be problematic and delays plague the project pipeline. Current estimates peg delays at between 6 24 months/ project with nearly 60% of delays closing in on two years. Grid curtailment issues and financing availability are the main culprits. In South and Central America wind deployment is focused in Brazil where a government auction scheme has encouraged a recent boom in deployment. Brazilian wind has also benefitted from access to affordable financing from the Brazilian Development Bank, BNDES. Other emerging wind markets in the region, such as Chile and Argentina, have seen small amounts of installed capacity and suffer from relatively expensive equipment and financing costs. The least developed region for onshore wind is the Middle East and Africa where South Africa, Israel and Kenya lead in terms of installed capacity. South Africa has over 100MW financed, but financing costs can run upwards of 1000bps over LIBOR. Offshore wind Almost 95% of the roughly 4GW of global installed offshore wind capacity is situated in the waters off Europe s western coast. Within that region the focal points are the UK and Germany. As a result, offshore wind LCOEs are a function of the costs of just over 50 projects located in that region, and a thorough understanding of how costs differ in other regions will likely result only from additional capacity deployment. This is set to change in the coming years as China, South Korea and other new entrants expand their installed bases. Nearly 2GW of offshore wind came online in 2012, 93% of which was in European waters. By 2020

19 World Energy Council 2013 Cost of Energy Technologies 17 that figure will be down to 60% and China on its own will account for nearly 30% of capacity installed. Note that offshore wind CAPEX is exclusive of grid-connection charges. The financing of offshore wind projects differs substantially from that for other renewable sources due to the sheer magnitude of the projects. Most of the projects financed over the past year have been over valued at over USD1bn with two projects over USD2bn. At these sizes complex financing structures are required and many deals involved the participation of numerous commercial banks and one or more multilateral development banks. Table 3 Levelised cost of offshore wind by country Source: Bloomberg New Energy Finance Geography CAPEX (USDm/MW) Western Europe OPEX (USD/MW/yr) 100, ,000 Capacity factor (%) LCOE (USD/MWh) As a percentage of LCOE, O&M costs make up a substantially higher portion of end costs for offshore wind than for onshore wind. The harsh environments inherent at sea and the higher degree of difficulty in accessing sites and transporting equipment are key drivers of these costs. Turbines are the main component of offshore CAPEX, representing approximately 30 40% of total costs. The market for offshore turbines is much more concentrated that that of onshore, with Siemens alone making up nearly 60% of historical and forecasted installed capacity from Scale is another major differentiator turbine sizes for the offshore market can reach as large as 6MW each. Other key drivers are foundations and the cost of installation, which can vary substantially as a function of sea depth. Bottlenecks such as access to installation vessels and construction of offshore grid infrastructure are causing delays in the industry, which increase contingency costs. Grid connection charges vary but can represent around 20% of total CAPEX costs; although for the purposes of this report those costs are excluded. Tax represents about 25% of the LCOE, which is much higher than the 19% for onshore wind. One of the key drivers here is that it is assumed that onshore wind has greater access to debt financing, which leads to a higher interest expense thereby reducing the tax liability for onshore relative to offshore. North America has yet to commission any offshore wind projects due to persistent delays in the installation of announced projects and problems crossing legal regulatory and regulatory hurdles. Permissions and incentives to build offshore wind farms depend on the jurisdiction of the water, since different policies may apply in federal or state waters. The 485MW Cape Wind project recently confirmed sale of 75% of its potential output and reached several key financing milestones. Until successful commercial operation of this and other smaller projects it will remain difficult to accurately assess LCOEs in the United States. The Middle East & Africa and South America are not currently forecasted to be areas where offshore wind will be deployed in the coming decade and as such have been excluded from our analysis.

20 18 Cost of Energy Technologies World Energy Council 2013 Solar PV Global installed capacity for PV has historically been dominated by Europe where government incentive schemes have spurred large deployment, for example in Germany and Italy. From Europe accounted for 70 80% of total installations. That fell to 50% in 2012 and will continue to decline, likely to 20% by 2015, as China and Japan become the growth markets. The last few years have witnessed more or less consistent declines in the cost of modules and underlying components, pushing LCOEs lower and lower in a market increasingly dominated by Chinese suppliers. PV economics differ substantially between plants >1MW and smaller distributed retail or commercial rooftop plants. For this report we concentrate only on larger projects. Figure 6 Levelised cost of PV electricity over time, developed market average (USD/MWh) Source: Bloomberg New Energy Finance c-si c-si tracking Thin film Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q Feed-in tariffs driven growth combined with a rapid fall in module prices have made solar PV more competitive over recent years, spurring a boom in the sector. This rapid growth has prompted governments to scale back feed-in tariffs to avoid budget overshoot. In markets and locations with more expensive power, such as in parts of Germany, companies are now finding it more cost-effective to use the power from solar cells themselves referred to as auto-consumption rather than claim the feed-in tariff. Installation continues there: the country installed nearly 800MW in Q and over 1,000MW in Q even as feed-in tariffs for new installations fell driven in part by the trend towards auto-consumption. With the diminishing prospects in Western Europe attention is now focused on China and Japan, the new main drivers of the global PV market. In China, solar PV has relatively few barriers to growth. It is competitive with conventional energy for commercial users but is more expensive for residential consumers. Here, most of the 35GW capacity target for 2015 will therefore be met by large-scale, >1MW installations and distributed generation in the commercial sector. A 2020 target of 50GW solar PV generation exists, supported by a national feed-in tariff and a system of subsidies. A boom in solar installations is underway in Japan, with the country s new generous feed-in tariffs making solar PV a very attractive prospect. The program has incentivised a large build there, with nearly 800MW of approved capacity as of early Q2.

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